Coiled tubing drilling rig

ABSTRACT

A novel rotary table is secured to the top of a well&#39;s BOP simplifying the making up of sectional tubing joints used in some aspects of operations with coiled tubing. The rotary table comprises top a bottom stationary housing affixed to the BOP, a top housing supported on the bottom housing by an annular bearing, a split clamp to transferring the weight of the tubing to the top housing and seals between the top and bottom housings and between the top housing and the tubing. More preferably, a coiled tubing rig is provided having a frame, a tiltable mast, an injector reel, a tubing straightener and a jib crane in combination with the rotary table for increased functionality including drilling surface hole using coiled tubing. The mast tilts between two positions, either aligning coiled tubing and injector with the BOP or aligning a jib crane and tubing elevators for manipulating sectional tubing including BHA onto and through the rotary table.

FIELD OF THE INVENTION

[0001] The present invention relates to apparatus and a process fordrilling a well. More specifically, addition of a rotary table to thewellhead in combination with a coiled tubing rig and modificationsthereto enable drilling a borehole in the earth including boreholeadjacent the surface.

BACKGROUND OF THE INVENTION

[0002] The general background relating to coiled tubing injector unitsis described in U.S. Pat. No. 5,839,514 and 4,673,035 to Gipson whichare incorporated herein by reference for all purposes.

[0003] Coiled tubing has been a useful apparatus in oil field operationsdue to the speed at which a tool can be injected and tripped out of awell bore (round trip). Coiled tubing is supplied on a spool. Aninjector at the wellhead is used to grip and control the tubing forinjection and withdrawal at the well. Accordingly, it is known toconnect a bottom hole assembly (“BHA”) to the bottom of the coiledtubing and run it into the well bore using the injector. A BHA mayinclude measuring and sampling tools, each being sectional and which arethreaded together in series. A BHA may also include drill collars forweight. Further, use of downhole motors and coiled tubing became morepopular when drilling deviated wells as it made more sense to limitdrilling rotation to the bit and not the entire string which must flexthrough a turn.

[0004] As stated, coiled tubing has more recently become a contender inthe drilling industry, due to the potential to significantly speeddrilling and reduce drilling costs through the use of continuous tubing.The most significant cost saving factors include the reduced pipehandling time, pipe joint makeup time, and reduced leakage risks.

[0005] In spite of the significant potential cost savings through theuse of coiled tubing, there are certain aspects of the associatedapparatus and process which have limited its application to drilling.

[0006] Coiled tubing has been unable to cope with all stages of thedrilling and have required the assistance of conventional rigs forhandling jointed tubing for certain aspects of drilling a well. Forexample, coiled tubing has not been successfully used to drill surfacehole due in part to a lack of bit weight at surface or shallow depths,lack of control over the coiled tubing's residual bend and the generallyuneven strata at surface, such as glacial residue. Typically then, aseparate and conventional rig is required to drill surface hole, placesurface casing, cement and then drill the vertical well portion.Thereafter, coiled tubing is used to re-enter and deepen the hole arelatively short distance (i.e., coiled tube drilling only the last,smallest and shallow portion). Generally, coiled tubing is used tore-enter the vertical hole and drill a relatively short and deviated orhorizontal lateral portion.

[0007] Further, after drilling, a separate rig is brought in to run inthe sectional and tubular production casing.

[0008] Several restrictions are placed on the use of coiled tubing. Onerestriction is related to the inability to rotate coiled tubing. Aconventional rotary drilling rig rotates the entire drill string fromthe surface for rotating a rotary drill bit downhole. The continuouscoiled tubing is supplied from a spool at surface and cannot be rotated.Accordingly, a BHA including a downhole motor and drill bit is connectedto the bottom end of the coiled tubing. Further, the BHA is typicallythreaded together and thereby results in a laborious threading of themultiple components separate from the coiled tubing. It is sometimesdesirable to increase the weight on the bit early in the drilling andthus a few lengths of conventional drill collars might be to threadedonto the BHA.

[0009] The injector is typically located at the wellhead and must be setaside to permit the larger diameter BHA to be placed through thewellhead and into the hole. Further, when running in, the wellheadinjector tends to inject tubing which has residual bend therein. Aresidual bend can result in added contact and unnecessary forces on thewalls of the hole, resulting in increased frictional drag and anoff-centered position of the tubing within the hole. Occasionally thecoiled tubing wads up in the hole (like pushing a rope through a tube)and cannot be injected any further downhole or ever reach total depth.

[0010] Therefore, in practice, the above problems result in the need formultiple rigs; a conventional rig to drill and place surface casing,coiled tubing for the remainder of the drilling and a conventional rigagain to place the production casing. Besides the duplicity for much ofthe equipment and personnel, such as pumping equipment, much time islost in assembling the BHA.

[0011] For example, a conventional rig may take two days to spud in,drill surface casing, and cement the casing. The crew manually makes upa BHA, requiring in the order of 6 hours. A separate crane is generallyemployed to lower the BHA through the wellhead, the BHA being supportedtemporarily on slips. If weight is required, one or more drill collarsare manually threaded into the BHA supported at the wellhead. Finally, aprior art coiled tubing rig is set up and connected to the BHA, injecteddown the surface casing and drilling may then begin. After drilling, thecrane is again employed to withdraw the BHA from the well. Lastly aconventional rig is brought in again to place the jointed productioncasing.

[0012] Coiled tubing rigs, while faster, have a much higher capital costand operating cost. The repeated plastic deformation of the coiled tubemeans it must be replaced often to avoid failure. Further, the rigincorporates spools, related equipment and pumps. The pumps andoperating costs are greater due to the relatively small diameter of thecoiled tubing, requires greater fluid horsepower to deliver mud to thedownhole motor.

[0013] Thus, it is an objective to use the coiled tubing rig for agreater portion of the on-site operations, reduce the on-site timegenerally and improve the drilling process.

SUMMARY OF THE INVENTION

[0014] A novel combination of components has resulted in a novel coiledtubing rig capable of superior handling and drilling.

[0015] Through the addition of a novel rotary table to the well site,preferably secured to the top of the wellhead or BOP, sectional tubularcomponents can be readily handled and the capabilities of a coiledtubing rig are markedly enhanced, now being able to easily make up BHAand yet retain the convenience and speed of a coiled tubing rig.

[0016] In a preferred embodiment of the invention, a coiled tubing rigis provided having a frame, a mast, an injector reel, a tubingstraightener and a jib crane. In combination with the rotary table, thetime required for spudding in and drilling 1100 meters of well is onlyabout {fraction (1/2)} to {fraction (1/3)} of the time of a jointedtubing rig. Specifically, this is accomplished by tilting the mastbetween two positions, one with the coiled tubing injector aligned withthe wellhead and a second with the injector out of alignment so as topermit the jib crane to align with the wellhead. The jib crane handleslong lengths of BHA, threaded tubular components or other jointedsections between the wellhead and coiled tubing. The jib manipulates theBHA onto and through the rotary table. The rotary table supports thejointed BHA sections so that they are easily rotated while beingsupported so as to quickly make up threaded joints. Tilting the injectorback over the wellhead, the BHA is attached to the coiled tubing so asto commence drilling. Preferably, the injector is mounted high above thewellhead so aid in the BHA handling. The straightener delivers straightcoiled tubing which is directed through a supporting stabilizer. Evenmore preferably, adding power tongs to the jib crane and coupling thatwith the tilting capability of the mast enables jointed productioncasing to be quickly run in without need for another rig on site.

[0017] As a result of the above combination, the preferred coiled tubingrig is able to drill surface hole, place jointed surface casing, quicklymake up jointed BHA, drill the well, withdraw the coiled tubing, quicklyremove the BHA, and place jointed production casing.

[0018] Therefore, in a broad apparatus aspect of the invention, a rotarytable is provided for the supported rotation of BHA or other sectionalcomponents at the wellhead comprising:

[0019] a bottom stationary housing affixed to the top of the wellhead;

[0020] a top rotational housing;

[0021] means such as slips or a split clamp for transferring the weightof the BHA to the top housing;

[0022] an annular bearing installed between the top and bottom housings;and

[0023] seals between the top and bottom housings and between the tophousing and the BHA.

[0024] Preferably the seal is an inflatable packer.

[0025] In another broad apparatus aspect of the invention, a coiledtubing rig, implemented in combination with the rotary table, creates ahybrid apparatus capable of superior site set-up, handling andfunctionality. More particularly, the apparatus comprises:

[0026] a coiled tubing rig having a frame and a mast normally alignedover a wellhead, an injector located in the mast and a tubingstraightener positioned between the injector and the wellhead;

[0027] a rotary table affixed to the well head;

[0028] a jib crane mounted atop the mast; and

[0029] means for pivoting the mast between two positions, a firstposition where the mast, injector and straightener are aligned with thewellhead for injection and withdrawing of coiled tubing, and a secondposition with the mast pivoted out of alignment from the wellhead sothat the jib crane can align sectional tubing with the wellhead and besupported therefrom and be made up on the rotary table.

[0030] Preferably a stabilizer tube extends between the injector and thewellhead.

[0031] In another broad aspect of the invention, a method is providedcomprising the steps of:

[0032] providing a rotary table over the well, preferably secured to awellhead;

[0033] supporting tubular sections on the rotary table to enablerotation of adjacent sections for making up a drilling assemblyincluding a downhole motor and drill bit;

[0034] aligning a coiled tubing injector over the drilling assembly;

[0035] rotating the drilling assembly to make up to the coiled tubing;and

[0036] drilling the well through the rotary table.

BRIEF DESCRIPTION OF THE DRAWINGS

[0037]FIG. 1 is a side elevation view of the coiled tubing aspect of theapparatus, illustrated in a road transport mode, and constructedaccording to an embodiment of the present invention

[0038]FIG. 2 is an overall side elevation view of the apparatusaccording to FIG. 1, arranged over a well bore in an injecting/drillingposition;

[0039]FIG. 3 is a side elevation view of the apparatus according to FIG.2, wherein the mast is tilted out of alignment from the wellhead forhanding lengths of tubing and BHA;

[0040]FIG. 4 is a partial side and exploded view of the rotary tablewith a flow tee incorporated therein. The bottom housing is flanged tothe BOP and the top housing is shown separated from the bottom housing;

[0041]FIG. 5 is an upward perspective sectional view of jointedsectional tubing passing through the rotary table's top housing. Thetubing is fitted with a split clamp, both of which are ready to set downon the top housing for rotary capability;

[0042]FIGS. 6a-6 d are a variety of upward perspective views ofcomponents of the top housing. Specifically,

[0043]FIG. 6a is a view of the top housing;

[0044]FIG. 6b is a sectional view of the top housing, according to FIG.6a, illustrating, in dotted lines, installation of the ring bearing;

[0045]FIG. 6c is an exploded view of the three components of the ringbearing;

[0046]FIG. 6d is a view of an elastomeric seal for installation into theentrance of the top housing for sealing about a jointed section passingtherethrough;

[0047]FIGS. 7a and 7 b are views of the top housing. Specifically.

[0048]FIG. 7a is a side sectional view of the top housing with the ringbearing installed; and

[0049]FIG. 7b is a top view of the top housing according to FIG. 7a.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

[0050] Having reference to FIG. 1, a coiled tubing injector is mountedon a mobile deck 11 such as a truck or trailer or on a separate frame(not shown) which could be slid or lifted onto or off of a truck ortrailer.

[0051] As disclosed in U.S. Pat. No. 5,839,514 to Gipson, a coiledtubing storage reel or spool 12 is mounted on a cradle 13, and coiledtubing 14 is stored thereon. The cradle 13 is attached to a traversingmechanism which allows the cradle to be reciprocated perpendicularly tothe axis of the deck 11.

[0052] An injector reel 20 is rotatably attached to the distal end 21 ofboom arm or mast 22. Mast 22 is attached at hinge member 23 to mastriser 24. Mast riser 24 is attached to the back end 25 of deck 11.

[0053] Having reference to FIG. 2, the injector reel 20 is furtherprovided with a drive mechanism 30 which includes a hydraulic drivemotor 31, a drive chain linkage 32, and sprocket assembly 33 extendingcircumferentially around the injector reel 20.

[0054] Reel support frame 34 also extends circumferentially around reel20 and supports a straightener assembly 35 and a hold down assembly 40.

[0055] Hold-down assembly 40 consists of a multiplicity of separate holddown mechanism 41. Twenty hold-down mechanisms 41 are mounted around aportion of the circumference of the injector reel 20 to exert pressureagainst the coiled tubing 14 over more than 90 degree of thecircumference of the injector reel 20.

[0056] The straightener 35 applies unequal pressure against the coiledtubing 14, plastically altering the curve of the tubing so that itleaves the straightener 35 as linear tubing, without any residual curve.

[0057] A hydraulically activated elevating work floor 50 is movablealong the working length of the mast 22 and particularly adjusts forvariable classes of Blow-out Preventor (BOP) 51 which, when fitted tothe well and wellhead can vary up to 2 meters in final installed height.

[0058] As shown in FIG. 2, in a first position, the mast 22 is raised bya mast lift cylinder 52, pivoting about hinge 23, to a tubing injectionposition generally perpendicular to the deck 11. Swing locks 53 (one oneach side of mast 22) are latched to secure the mast 22 and injectorreel 20 in the uplift position. In the first injecting position, coiledtubing 14 extends from the storage spool 12 up and over the injectorreel 20. The hold-down assembly 40 extends around a portion of thecircumference of the injector reel 20 to exert pressure on the coiledtubing 14 as it is straightened and injected into the well or returnedto the spool 12.

[0059] When the embodiment is in the injecting position, tubing 14 exitsthe injector reel 20 generally perpendicular to the ground. In caseswhere the drilling has progressed past the surface casing stage, whentubing 14 exits the injector reel 20 it is generally aligned with theBOP 51.

[0060] A telescoping tubing stabilizer 70 has an upper section 71 and alower section 72. The stabilizer 70 extends between the straightenerassembly 35 and the BOP 51 at the wellhead. The function of thestabilizer 70 is to ensure that the coiled tubing 22 does not bend orexcessively flex as it is being injected.

[0061] A swivel bushing 60 supports the upper section 71 of thetelescoping tubular stabilizer 70 where it connects to the straightenerassembly 35. A misaligning union 61 between the stabilizer's uppersection 71 and the straightener 35 allows for misalignment of thestabilizer with respect to the BOP 51 with no adverse effects. Ahydraulic winch 62 mounted on the mast 22 is used to collapse and extendthe stabilizer 70.

[0062] The mast 22 is fitted with a jib crane 73 and hoist 74. The hoist74 has a travelling block 75. Bales and an elevator 76 are hung from theblock 75 for lifting lengths of casing, tubing and the like.

[0063] Rather than use a separate crane to lift and lower long lengthsof sectional tubing (e.g. 30 feet long) at the well, the jib crane 73extension is provided from the mast 22. Further, to enable alignment ofsectional tubing 15 over the BOP 51, the coiled tubing rig injector 20must be moved out of its working alignment from the BOP 51. Accordingly,the mast 22 is pivotable adjacent the BOP 51 so as to tilt it out of theway and permit the jib crane 73 access to the BOP.

[0064] Once a Bottom Hole Assembly (BHA) or other sectional tubularcomponents 15 are placed at or through the BOP, there must be meanscapable of making up the threaded joints.

[0065] Having reference to FIGS. 4-7 b, mounted atop the BOP 51 is arotary table 100 which comprises top and bottom housings 101,103, spacedapart by a ring bearing 102. As shown in FIG. 4, the bottom housing 103is incorporated into a flow tee 104. Generally, the flow tee 104 ispositioned directly above the BOP 51. The top and bottom housings101,103 have a bore 105 which is complementary to the BOP 51 andwellhead, suitable for passing the coiled tubing 14 and also jointedsections such as the BHA.

[0066] The bottom housing 103 comprises an upstanding sleeve 106 havingan intermediately located and radially outward projecting annular bottomshoulder 107. The top housing 101 has a downward extending sleeve 108and an intermediately located inwardly projecting annular top shoulder109. The upstanding sleeve 106 of the bottom housing 103 fits closelythrough the top shoulder 109. The downward sleeve 108 of the top housing101 fits closely over the bottom shoulder 107. O-Ring seals 110 at thenose of each of the top and bottom shoulders 109,107 seal against thebottom and top housings sleeves 106,108 respectively.

[0067] The ring bearing 102 is sandwiched between the top and bottomannular shoulders 109,107, permitting the top housing 101 to rotatefreely on the bottom housing 103.

[0068] The top housing 101 is retained to the bottom housing 103 using athreaded collar 111 located below the bottom shoulder 107. The collar111 is threaded onto the top housing's sleeve 108, pulling the tophousing 101 onto the bottom housing 103, loading the ring bearing 102therebetween.

[0069] Best shown in FIG. 6a, the ring bearing 102 is sectionalcomprising a top race 112, a bottom race 114 and an intermediate cagering 113 fitted with a multiplicity of ball bearings 115. In FIG. 4, onecan see that, when assembled, the bottom race 114 is seen to besupported by and rests on the bottom shoulder 107. The cage ring 113rests on the bottom race 114 and the top race 112 bears against the cagering 113.

[0070] In FIG. 5, the top housing 101 seen to provide a general servicerotary section 120 supported on the ring bearing 102 rotation about thevertical axis 20 of the BOP 51.

[0071] The rotary section 120 further incorporates means 121 forcontrollably and periodically gripping the jointed sections 15 whileoperations are performed. Gripping means 121 are installed to grip thejointed section 15 and form a bottom surface 122 for transmitting theweight of the gripped jointed sections through the top housing 101 andinto the annular bearing 102. Thus, the jointed sections 15 areprevented from being lost down the well yet, are easily rotated on theannular bearing 102 for making up successive threaded joints of tubing15.

[0072] The gripping means 121 are typically a slip arrangement or asplit clamp. After the gripping means 121 are secured about the jointedsection 15, it bottom surface 122 is lowered into engagement with thetop housing 101 or rotary section 120 and the top housing bears againstthe top race and transmits the weight of the jointed section 15 into theBOP 51 while permitting it to rotate. Typically, it is inconvenient toaccess the end of the jointed section 15 to apply the gripping means121. Accordingly, the gripping means 121 can be applied to support atthe mid-point of a length of tubing.

[0073] One conventional form of gripping means (not shown) include aplurality slip type gripping units (not shown). Circularly spaced wedgeslips have outer tapering surfaces which engage correspondingly taperedsurfaces of the rotary section to cam the slips inwardly in response todownward movement thereof. The inner gripping faces of the slips areformed with teeth or other irregularities adapted to engage the outersurface of the jointed section to transmit tubing weight into the rotarysection and support it in the well.

[0074] Another form of rotary section gripping means 121 is a splitclamp (FIG. 5) having a cylindrical body split diametrically into twobody halves 123. Two body halves 123 have facing semicircular recessesor gripping surfaces 124 and are positioning on either side of thetubing 15 to be supported. The two body halves 123 are sized so thatwhen clamped about tubing 15, they do not bottom against each other, thediametral depth of their combined recesses 124 being less than thediameter of the jointed section 15.

[0075] When clamped about the tubing 15, the two body halves 124 combineto become the cylindrical body of the split clamp gripping means 121which then rests upon the top housing 101.

[0076] A BHA can now be made up by supporting each jointed section 15through the BOP 51, supported by the split clamp boy halves 123,123 andtop housing 101 and be rotated while using chain tongs to tightenjoints. Further, the completed and heavy BHA can be rotated freely andsupported on rotary section 120 so as to thread it onto the connectionto the non-rotating coiled tubing 14. As shown in FIGS. 5 and 6c, oncethe tubing 15 is through the top housing, an inflatable packer 116 isinflated to seal the tubing 15 therein.

[0077] By implementing the rotary table 100 as described, it has beenfound that usual BHA make up time of about 6 hours can now beaccomplished in about 0.5-1.0 hours.

[0078] Further, once spudded in and surface casing is placed, thepreferred coiled tubing rig can drill 1100 meters of hole and haveproduction casing placed, including cement, in about 16 hours, fasterthan that of a conventional jointed tubing rig by about 24-30 hours. Thesurface hole can be drilled using sectional tubing 15 or using thecoiled tubing 14. Surface casing run in with the jib 73 and elevators76.

[0079] The preferred injector 20 is capable of up to 15,000 lb. forceand it with PDC bits (polycrystalline diamond compact, typically needingonly about 9,000 lbf) may not even be necessary to use additional drillcollars for weight. Drill collars may yet be added for stabilization toaid in keeping the surface hole straight.

The embodiments of the invention for which an exclusive property ofprivilege is claimed are defined as follows:
 1. A rotary table for thesupported rotation of sectional tubular components which extend througha bore in a wellhead comprising: (a) a bottom stationary housing affixedto the top of the wellhead and having a bore contiguous with thewellhead; (b) a top rotational housing having bore a contiguous with thebottom housing; (c) means for transferring the weight of the componentsto the top housing; (d) an annular bearing installed between the top andbottom housings for rotationally supporting the weight of the componentsand having bore contiguous with the top and bottom housings; (e) a sealbetween the top and bottom housings; and (f) a seal between the tophousing and the components passing therethrough so that the componentscan be rotationally supported through the wellhead, the wellhead seal ismaintained and the components can be rotated.
 2. The rotary table ofclaim 1 wherein the means for transferring the weight of the componentsto the top housing is a split clamp.
 3. The rotary table of claim 2wherein: (a) the bottom housing has an upward tubular protuberanceformed with an annular and radially outwardly extending shoulder uponwhich the annular bearing is supported; and (b) the top housing has anannular shoulder extending radially inwardly from the bore so that, whenthe top housing is telescoped over the protuberance, the inward shoulderbears against and is supported on the annular bearing.
 4. The rotarytable of claim 3 wherein: (a) the protuberance's shoulder is fitted witha circumferential outer seal for sealing against the bore of the tophousing; and (b) the top housing's shoulder is fitted with acircumferential inner seal for sealing against the protuberance.
 5. Therotary table of claim 4 further comprising means for retaining the tophousing to the bottom housing.
 6. The rotary table of claim 5 whereinthe retaining means comprises an annular collar rotatably fitted betweenthe wellhead and the protuberance's shoulder, the collar extending aboutthe protuberance's shoulder to engage the top housing and draw the tophousing to the bottom housing, retaining them together.
 7. The rotarytable of claim 6 wherein the annular collar has female threads forengaging male threads on the top housing.
 8. The rotary table of claim 4wherein flow tee is incorporated into the bottom housing.
 9. Hybridapparatus for operation with both coiled and sectional tubing apparatuscomprising: (a) a coiled tubing rig having a frame and a mast normallyaligned over a wellhead, an injector located in the mast and a tubingstraightener positioned between the injector and the wellhead; (b) arotary table affixed to the well head for rotationally supportingsectional tubular components passing through the wellhead; (c) a jibcrane mounted atop the mast; and (d) means for pivoting the mast betweentwo positions, (i) a first position where the mast, injector andstraightener are aligned with the wellhead for injection and withdrawingof coiled tubing, and (ii) a second position with the mast pivoted outof alignment from the wellhead so that the jib crane can align sectionaltubing with the wellhead and be supported therefrom and be made up onthe rotary table.
 10. The hybrid apparatus of claim 9 wherein thesectional tubing is a BHA.
 11. The hybrid apparatus of claim 10 furthercomprising power tongs for enabling sectional production casing to bequickly made up and run in through the wellhead.
 12. A method ofdrilling a well using coiled tubing comprising the steps of: (a)providing a rotary table over the well; (b) standing tubular sections onthe rotary table to enable rotation of adjacent sections for making up adrilling assembly including a downhole motor and drill bit; (c) aligninga coiled tubing injector over the drilling assembly; (d) rotating thedrilling assembly to make up to the coiled tubing; and (e) drilling thewell through the rotary table.
 13. The method of claim 12 furthercomprising: (a) spudding a well with a conventional drilling rig andinstalling a wellhead; and (b) fitting the rotary table to the wellhead.14. The method of claim 13 wherein the drilling assembly comprises aBHA.
 15. The method of claim 14 further comprising; (a) positioning acoiled tubing rig over the well, the rig having a mast with a jib crane,an injector being mounted in the mast's top with a straightener mountedbetween the injector and the well; (b) moving the injector andstraightener out of alignment for lifting tubular sections and standingthem on the rotary table for making up the drilling assembly; and (c)moving the injector and straightener into alignment with the rotarytable for making up the drilling assembly to the coiled tubing. 16.Hybrid apparatus for operation with both coiled and sectional tubingapparatus comprising: (a) a coiled tubing rig having a frame and a mastnormally aligned over a wellhead, an injector located in the mast and atubing straightener positioned between the injector and the wellhead;(b) a rotary table affixed to the well head for rotationally supportingsectional tubular components passing through the wellhead; (c) a jibcrane mounted atop the mast; and (d) means for pivoting the mast betweentwo positions, (i) a first position where the mast, injector andstraightener are aligned with the wellhead for injection and withdrawingof coiled tubing, and (ii) a second position with the mast pivoted outof alignment from the wellhead so that the jib crane can align sectionaltubing with the wellhead and be supported therefrom and be made up onthe rotary table.